This method answers two current challenges: 1) how to enhance the efficiency of through-wellbore extraction of subsoil resources and 2) how to improve the profitability of the extraction regime.
A key strategy in enhancing the efficiency of through-wellbore recovery of subsoil resources and improving the profitability of the extraction regime is to increase the temperature of target formations to intensify the extraction process.
As of today, these technologies are considered cutting-edge and hold considerable promise for future refinement.
For example, increasing oil recovery from target formations by up to 50-60% by raising the temperature of these formations is equivalent to doubling the volume of commercial oil reserves. By elevating the temperature of a reservoir to 120° C., oil recovery from that formation may be increased by 80%.
Increasing the temperature of reservoirs during through-wellbore recovery of rare, radioactive, non-ferrous and precious metals reduces the time needed to convert these resources into a solution and consequently, accelerates the development of said resources by several times while simultaneously raising their respective recovery factors.
Controlling the temperature field during underground extraction of sulfur will make it possible to localize said temperature field within the reservoir, lower the cost of recovery and reduce the environmental impact of the process.
Heating a gas reservoir blocked by water, process fluid or retrograde condensate solves the costly problem of eliminating the blockage and will therefore reduce the time required for reservoir development while increasing gas recovery.
An essential requirement of this process is to achieve optimum control of the temperature regime for each type of resource to be recovered.
Documented methods exist for through-wellbore recovery of subsoil resources (hydrocarbons) based on heating a reservoir by injecting it with pressurized hot water or superheated steam.
This approach consists of thermal-steam treatment of a reservoir by heating water to a temperature lower than its evaporation point in specially designed heating units located on the surface, and then injecting the heated water through the wellbore into the target formation. A more effective variant of this method is to heat the water to the temperature of superheated steam prior to injection.
The main drawbacks of thermal-steam treatment are:                rapid water-cutting of the target resource;        negative impact of high temperatures on the wellbore and wellhead equipment;        destruction of the rock matrix accompanied by extensive sand sloughing into the wellbore;        spontaneous formation of oil/water emulsions.        
The field of application of thermal-steam treatment for oil reservoirs is limited to the following:                oil-saturation is less than 40%;        porosity is less than 20%;        oil-saturated thickness is no less than 6 m.;        permeability is less than 100*10−3 μm2;        net-to-gross ratio is less than 0.5;        a high degree of permeability stratification is present;        oil viscosity is high (greater than 1000 mPa*s);        reservoir-scale fracturing is present;        zonal heterogeneity of permeability is present within the reservoir;        high degree of reservoir discontinuity is present;        the depth of reservoir occurrence is significant (more than 1000 m) and reservoir pressure is high;        rock pressure in shallower reservoirs is too low to avoid hydraulic fracturing of the reservoir during steam injection.        
The process of thermal-steam treatment is effective when the steam /oil ratio is less than 13 t/t (amount of steam per metric ton of oil). It is documented that one metric ton of oil must be burned to obtain 13 tons of steam.
The closest approximation to the technical solution presented in this disclosure is primarily focused on the recovery of liquid hydrocarbons [2] and includes penetrating a reservoir with conventional wells and generating thermal energy directly within said formation via in-situ combustion (fireflooding). Fireflooding is a thermal oil production method that is based on generating heat directly within an oil reservoir as opposed to thermal treatment, which involves injecting a thermal agent downhole into the reservoir from the surface.
When performing this method of fireflooding, in-situ oil combustion is initiated and maintained via the injection of air. The oxygen in the air reacts with fuel (oil), forming CO2 and water, accompanied by the release of heat. The amount of energy (heat) thus released will depend on the composition of the crude oil. The burning of heavy oils will result in the release of approximately 42-46 thousand kj/kg of energy.
In some reservoirs, the oil may ignite spontaneously, while in others, preliminary heating will be required.
The chemical reaction between the oxygen contained in injected air and the in-situ oil may also result in the release of heat without combustion. Depending on the composition of the oil, the speed of this oxidation process may be sufficient to increase temperature to a point at which the oil is ignited. Otherwise, oil combustion may be initiated with the help of bottomhole heaters, or by injection of pre-heated air or preliminary injection of highly reactive oil, or through the use of combustion catalysts.
Other deficiencies inherent in this method of in-situ combustion are the following:                inefficient distribution of heat during in-situ combustion resulting from the fact that a significant heating zone forms behind the combustion front;        damage to bottomhole equipment and the well casing of producing wells under the impact of temperature (up to 650° C.) and the onset of corrosion after propagation of a combustion front;        reduced productivity resulting from gravitational stratification of the oil, occurring when air is channeled through the oil in the reservoir;        environmental contamination caused by emission of harmful combustion products into the atmosphere during in-situ combustion;        strong dependency of economic performance on reservoir and oil properties during in-situ combustion.        
It should be noted that the following features of oil production via in-situ combustion may also be considered inadequacies of the method.
The parameter that best measures the cost effectiveness of the process of in-situ combustion is the ratio between the volume of injected air and the volume of oil produced through in-situ combustion. Experience has shown that when in-situ combustion is successfully implemented, this ratio is equal to 3600 m3/m3.
Furthermore, large volumes of an oxidizing agent (air, oxygen) must continuously be injected into the reservoir to maintain the combustion process. But this is only possible when the reservoir is adequately permeable. In many cases, permeability is too low and very unevenly distributed.
The reaction between oxygen and crude oil begins to intensify as temperature is increased, and the oil may auto-ignite sometime after a temperature of 100-150° C. has been reached.
At a temperature of approximately 260° C., hydrogen in the oil combusts and water and coke are exuded.
Coke burns at a temperature of 370° C.
Within the zone of the combustion front, heavy fuel (coke) burns at temperatures from 315° C. to 650° C.
Coke combustion requires the consumption of enormous amounts of air, thereby making it unprofitable to produce oil containing large amounts of heavy hydrocarbons.
Free oxygen may pass through the combustion front or bypass it through channels in the rock, creating serious safety issues in producing wells.
The in-situ combustion method is primarily used for oil production, and is not designed for the through-wellbore extraction of other subsoil resources.
The present invention fulfills these needs and provides other related advantages.